Method for inverting reflection trace data from 3-D and 4-D seismic surveys and identifying subsurface fluid and pathways in and among hydrocarbon reservoirs based on impedance models

• US 5,798,982 A
• Filed: 04/29/1996
• Issued: 08/25/1998
• Est. Priority Date: 04/29/1996
• Status: Expired due to Fees

• Current Assignee: Trustees Of Columbia University In The City Of New York (Columbia University)
• Original Assignee: Trustees Of Columbia University In The City Of New York (Columbia University)
• Inventors: He, Wei, Anderson, Roger N.
• Primary Examiner(s): Moskowitz, Nelson
• Application Number:
  US08/641,069
• Time in Patent Office: 848 Days
• Field of Search: 367/28, 367/29, 367/73, 364/421, 364/422
• US Class Current: 367/73
• CPC Class Codes: G01V 1/306 for determining physical properties of the subsurface, e.g. impedance, porosity or attenuation profiles

Abstract

A method is disclosed for inverting 3-D seismic reflection data obtained from seismic surveys to derive impedance models for a subsurface region, and for inversion of multiple 3-D seismic surveys (i.e., 4-D seismic surveys) of the same subsurface volume, separated in time to allow for dynamic fluid migration, such that small scale structure and regions of fluid and dynamic fluid flow within the subsurface volume being studied can be identified. The method allows for the mapping and quantification of available hydrocarbons within a reservoir and is thus useful for hydrocarbon prospecting and reservoir management. An iterative seismic inversion scheme constrained by actual well log data which uses a time/depth dependent seismic source function is employed to derive impedance models from 3-D and 4-D seismic datasets. The impedance values can be region grown to better isolate the low impedance hydrocarbon bearing regions. Impedance data derived from multiple 3-D seismic surveys of the same volume can be compared to identify regions of dynamic evolution and bypassed pay. Effective Oil Saturation or net oil thickness can also be derived from the impedance data and used for quantitative assessment of prospective drilling targets and reservoir management.

Claims

1. A method for constructing one or more impedance models of a subsurface volume comprising:

(a) obtaining one or more 3-D seismic image of the subsurface volume from observed seismic reflection trace data derived from seismic surveys;

(b) constructing an a priori impedance model of the subsurface volume based on estimated impedance trends within the subsurface volume, said a priori impedance model initially being substantially identical for each seismic image in recognition that basic lithologic structure remains substantially unchanged during the time interval between seismic surveys;

(c) creating a model of the seismic reflection trace data for the subsurface volume based on the a priori impedance model by combining the a priori impedance model with a seismic source function or wavelet which is time/depth dependent throughout the subsurface region being modeled;

(d) comparing the model and the observed seismic reflection trace data for each seismic image obtained and, if the model seismic reflection trace data and observed seismic reflection trace data vary by more than preselected tolerances, modifying the a priori impedance model corresponding to each seismic survey such that the variation between model and observed seismic reflection trace data will be decreased; and

(e) iteratively repeating steps (c) and (d) until the model seismic reflection trace data and observed seismic reflection trace data variations are less than the preselected tolerances.

2. The method of claim 1 wherein:

(a) the a priori impedance model initially constructed in claim element 1(b) is the impedance compaction trend derived from well log data within the subsurface volume; and

(b) the a priori impedance model corresponding to each seismic survey is modified per claim element 1(d) by computing a covariance function using the model and observed seismic reflection trace data to derive changes to be made to the a priori impedance model.

3. The method of claim 1 wherein the seismic source function or wavelet is the time/depth dependent autocorrelation function of the observed seismic reflection trace data.

6. The method of claim 4 where the impedance model of the subsurface volume is constructed pursuant to the steps of claim 1.

7. The method of claim 4 where the impedance model of the subsurface volume is constructed pursuant to the steps of claim 2.

8. The method of claim 4 where the impedance model of the subsurface volume is constructed pursuant to the steps of claim 3.

9. The method of claim 5 where the impedance model of the subsurface volume is constructed pursuant to the steps of claim 1.

10. The method of claim 5 where the impedance model of the subsurface volume is constructed pursuant to the steps of claim 2.

11. The method of claim 5 where the impedance model of the subsurface volume is constructed pursuant to the steps of claim 3.

13. The method of claim 8 where the extent of regions associated with hydrocarbons based on the impedance model is accomplished by region growing impedance data samples within the subsurface volume to a preset threshold.

14. The method of claim 12 wherein the impedance model of the subsurface volume for each seismic image is constructed pursuant to the steps of claim 1.

17. The method of claim 13 wherein the impedance model of the subsurface volume for each seismic image is constructed pursuant to the steps of claim 1.

18. The method of claim 13 wherein the impedance model of the subsurface volume for each seismic image is constructed pursuant to the steps of claim 2.

19. The method of claim 13 wherein the impedance model of the subsurface volume for each seismic image is constructed pursuant to the steps of claim 3.

26. The method for quantifying hydrocarbon bearing characteristics of a reservoir for reservoir management of claim 20 wherein the small-scale structure and regions of fluid and dynamic fluid flow within the reservoir are identified pursuant to the steps of claim 10.

27. The method for quantifying hydrocarbon bearing characteristics of a reservoir for reservoir management of claim 20 wherein the small-scale structure and regions of fluid and dynamic fluid flow within the reservoir are identified pursuant to the steps of claim 11.

4. A 4-D time dependant method of identifying small-scale structure and regions of fluid and dynamic fluid flow within a hydrocarbon reservoir within a subsurface volume, comprising:

(a) obtaining a plurality of 3-D seismic images of a subsurface volume from seismic reflection traces, said images being spaced in time to allow for dynamic evolution of the hydrocarbon reservoir within the subsurface volume;

(b) processing the plurality of seismic images such that they are coincident in spatial extent orientation and resolution, and normalizing the seismic reflection trace amplitudes so the plurality of 3-D seismic images may be compared;

(c) constructing an impedance model of the subsurface volume including the hydrocarbon reservoir for each seismic image;

(d) identifying impedance attributes associated with the impedance model which are correlated with the presence of hydrocarbons within the subsurface volume for each seismic image;

(e) establishing for each seismic image the extent of regions associated with hydrocarbons based on the impedance model; and

(f) identifying intra-reservoir structure by analyzing the differences between the data samples associated with the regions associated with hydrocarbons within the reservoir for each seismic image.

5. The method of claim 4 where the extent of regions associated with hydrocarbons based on the impedance model is accomplished by region growing impedance data samples within the reservoir to a preset threshold.

20. A method for quantifying hydrocarbon bearing characteristics of a reservoir for reservoir management comprising:

(a) identifying small-scale structure and regions of fluid and dynamic fluid flow within the reservoir pursuant to the steps of claim 4; and

(b) converting impedance values of the reservoir into quantitative values of recoverable hydrocarbons, such as oil saturation or oil thickness, within the reservoir.

21. The method for quantifying hydrocarbon bearing characteristics of a reservoir for reservoir management of claim 20 wherein the extent of regions associated with hydrocarbons based on the impedance model is accomplished by region growing impedance data samples within the reservoir to a preset threshold.

22. The method for quantifying hydrocarbon bearing characteristics of a reservoir for reservoir management of claim 20 wherein the small-scale structure and regions of fluid and dynamic fluid flow within the reservoir are identified pursuant to the steps of claim 6.

23. The method for quantifying hydrocarbon bearing characteristics of a reservoir for reservoir management of claim 20 wherein the small-scale structure and regions of fluid and dynamic fluid flow within the reservoir are identified pursuant to the steps of claim 7.

24. The method for quantifying hydrocarbon bearing characteristics of a reservoir for reservoir management of claim 20 wherein the small-scale structure and regions of fluid and dynamic fluid flow within the reservoir are identified pursuant to the steps of claim 8.

25. The method for quantifying hydrocarbon bearing characteristics of a reservoir for reservoir management of claim 20 wherein the small-scale structure and regions of fluid and dynamic fluid flow within the reservoir are identified pursuant to the steps of claim 9.

12. A method of identifying large-scale structure and migration pathways of hydrocarbon bearing regions within a subsurface volume, comprising:

(a) obtaining a 3-D seismic image of the subsurface volume from seismic reflection traces;

(b) constructing an impedance model of the subsurface volume;

(c) identifying impedance attributes associated with the impedance model which are correlated with the presence of hydrocarbons within the subsurface volume; and

(d) establishing the extent of regions associated with hydrocarbons based on the impedance model.

15. The method of claim 12 wherein the impedance model of the subsurface volume for each seismic image is constructed pursuant to the steps of claim 2.

16. The method of claim 12 wherein the impedance model of the subsurface volume for each seismic image is constructed pursuant to the steps of claim 3.